Seismic surveying has become the primary tool of exploration companies in the continental United States, both onshore and offshore. Seismic surveying consists of three separate stages: data acquisition, data processing and data interpretation. The success of a seismic prospecting operation depends on satisfactory completion of all three stages.
A seismic survey is conducted by creating an impulsive or vibratory wave—a seismic wave—on or near the surface of the ground along a predetermined line, using an energy source. The seismic wave travels into the earth, is reflected by subsurface formations, and returns to the surface, where it receivers called geophones—similar to microphones—detect the signal and the data recorded. By analyzing the time it takes for the seismic waves to reflect off of subsurface formations and return to the surface, a geophysicist can map subsurface formations and anomalies and predict where oil or gas may be trapped in sufficient quantities for exploration and development activities.
Until relatively recently, seismic surveys were conducted along a single line on the ground, and their analysis created a two-dimensional picture akin to a slice through the earth, showing the subsurface geology along that line. This is referred to as two-dimensional or 2D seismic data.
Currently, almost all oil and gas exploratory wells are preceded by 3D seismic surveys. The basic method of testing is the same as for 2D, but instead of a single line of energy source points and receiver points, the source points and receiver points are laid out in a grid across the property. The receiver points are generally laid down in parallel lines (receiver lines), and the source points are generally laid out in parallel lines that are approximately perpendicular to the receiver lines in most modern surveys, although variations in layout are used.
The spacing of the source and receiver points is determined by the design and objectives of the survey. They may be several hundred feet apart or as close as 55 feet or even smaller for high-resolution surveys. The resulting recorded reflections received at each receiver point come from all directions, and sophisticated computer programs can analyze this data to create a three-dimensional image of the subsurface. After the data is processed, scientists and engineers assemble and interpret the 3D seismic information in the form of a 3D data cube that represents a display of subsurface features.
The area covered by the 3D grid must be larger than the subsurface area to be imaged, in order to acquire sufficient data for the area of interest. Generally, in order to acquire “full-fold data” for an area, source and receiver points must be laid out to half the spread length beyond the boundary of the area of interest build fold and be full fold at the edge of the area of interest. The additional data acquired in this “halo” on the outer edge of a 3D survey is sometimes called “tails.” The quality of the subsurface data at the edge of the survey will not ordinarily be sufficient to map and evaluate the subsurface of these “tail” areas.
Additionally, an area around the zone of interest must be added to properly migrate the data and image it correctly. This zone is called the migration apron or aperture and it is at generally greater then about 60% of the depth to the primary objective. Thus, even though the area of interest is small, three zones must be filled—the original area of interest, the migration apron necessary for the processor to image the zone of interest and finally the fold taper that the acquisitions group needs to acquire useable signal to noise ratio data for the processor to migrate into the zone of interest.
Seismic data is generally processed for the purpose of imaging seismic reflections for structural and stratigraphic interpretation. The quality of the seismic data that is ultimately used in the structural and stratigraphic interpretation depends on many different factors and varies from survey to survey. Steps that are omitted or not correctly completed in the data acquisition, data processing and data interpretation stages can greatly affect the quality of the final images or numerical representation of the subsurface features. The quality of the seismic data directly affects the reliability of observations and numerical measurements made from the seismic data and affects any decisions based on the seismic data.
Constructing accurate seismic images and corresponding earth models is important in making business or operational decisions relating to oil and gas exploration and reservoir management. For example, earth scientists use seismic images to determine where to place wells in subterranean regions containing hydrocarbon reservoirs. They also build models of the subsurface to create reservoir models suitable for reservoir fluid flow modeling. The quality of the business and operational decisions is highly dependent on the quality of the seismic images and earth models.
The known methods of analyzing the quality of the 3D seismic survey are flawed in some respects. Normally, bin fold maps are created, spider diagrams of the azimuth distributions are pulled and/or the partial fold of stack plots on the survey design are reviewed to obtain information regarding the overall potential for the quality of the survey. While these techniques relate information about the survey as a whole and attributes drawn from them are indicative of the quality of the survey, these techniques do not analyze the sampling of the survey or compared it to other surveys or take into account the possible variations in actual field implementation of the theoretic survey. Other techniques involve visual inspection of time slices through the fold and offset planes of proposed designs. However, the interpretation is influenced by a users experience and knowledge, and thus is somewhat subjective and not easily compared between users.
There exists a need for a more robust technique for analyzing the quality of a 3D seismic survey, preferably one that is not as subjective.